EP3500727B1 - Bohrlochbildgebung mithilfe von amplituden von gebrochenen akustikwellen - Google Patents

Bohrlochbildgebung mithilfe von amplituden von gebrochenen akustikwellen

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Publication number
EP3500727B1
EP3500727B1 EP16888549.9A EP16888549A EP3500727B1 EP 3500727 B1 EP3500727 B1 EP 3500727B1 EP 16888549 A EP16888549 A EP 16888549A EP 3500727 B1 EP3500727 B1 EP 3500727B1
Authority
EP
European Patent Office
Prior art keywords
borehole
acoustic
amplitude
refracted
ultrasonic wave
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Active
Application number
EP16888549.9A
Other languages
English (en)
French (fr)
Other versions
EP3500727A4 (de
EP3500727A1 (de
Inventor
Yao Ge
Wei Li
Jing Jin
Chung Chang
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services Inc
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Publication date
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Publication of EP3500727A1 publication Critical patent/EP3500727A1/de
Publication of EP3500727A4 publication Critical patent/EP3500727A4/de
Application granted granted Critical
Publication of EP3500727B1 publication Critical patent/EP3500727B1/de
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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/38—Processing data, e.g. for analysis, for interpretation, for correction
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • E21B47/0025—Survey of boreholes or wells by visual inspection generating an image of the borehole wall using down-hole measurements, e.g. acoustic or electric
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/08—Measuring diameters or related dimensions at the borehole
    • E21B47/085—Measuring diameters or related dimensions at the borehole using radiant means, e.g. acoustic, radioactive or electromagnetic
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/26—Storing data down-hole, e.g. in a memory or on a record carrier
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R33/00—Arrangements or instruments for measuring magnetic variables
    • G01R33/12—Measuring magnetic properties of articles or specimens of solids or fluids
    • G01R33/1223—Measuring permeability, i.e. permeameters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/48—Processing data
    • G01V1/50—Analysing data
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/26—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/32—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electron or nuclear magnetic resonance
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/34—Transmitting data to recording or processing apparatus; Recording data
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/46—Data acquisition
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/48—Processing data
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2200/00—Details of seismic or acoustic prospecting or detecting in general
    • G01V2200/10—Miscellaneous details
    • G01V2200/16—Measure-while-drilling or logging-while-drilling
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/60—Analysis
    • G01V2210/63—Seismic attributes, e.g. amplitude, polarity, instant phase

Definitions

  • the present disclosure relates generally to well logging systems and methods and, more specifically, to borehole acoustic imaging using the amplitude of refracted waves.
  • Well logging systems and methods may be used to inspect and evaluate many characteristics of the wellbore, wellbore casing, and the formations through which the wellbore traverses.
  • LWD logging-while-drilling
  • the pulse-echo technique employs a transducer which fires an ultrasonic pulse and receives the echo from the borehole.
  • This technique offers high resolution borehole images in both oil-based mud (“OBM”) and water-based mud (“WBM”) and has been used in wireline tools for more than 40 years.
  • OBM oil-based mud
  • WBM water-based mud
  • pulse-echo technique there are multiple challenges applying the pulse-echo technique to LWD, and one major challenge is eccentricity and motion compensation due to vibration.
  • the challenges are presented because pulse-echo signals are sensitive to multiple parameters, such as beam divergence, reflection angle, attenuation along propagation path, etc. All the factors need to be taken into account to acquire a complete deterministic compensation, which requires accurate motion sensing and motion algorithms.
  • Conventional approaches have been unable to solve these challenges, hence there is no acoustic tool commercially available for LWD borehole imaging.
  • conventional high resolution imaging tools for LWD are mainly based on micro-resistivity, which can only be used in water based mud.
  • the location of the fracture image can also be determined by back propagating the corresponding receiver location to the borehole, according to the oblique angle at which the refracted waves propagate (as shown in FIG. 4 ).
  • the angle is the critical angle of the refracted wave which can be calculated from the ratio between the refracted wave velocity and fluid velocity.
  • the subterranean region 1220 can include all or part of one or more subterranean formations or zones.
  • the subterranean region 1220 shown in FIG. 12A includes multiple subsurface layers 1222 and a wellbore 1204 penetrating the subsurface layers 1222.
  • the subsurface layers 1222 can include sedimentary layers, rock layers, sand layers, or combinations of these other types of subsurface layers.
  • One or more of the subsurface layers can contain brine, oil, gas, etc.
  • wellbore 1204 shown in FIG. 12A is a vertical wellbore
  • the logging system 1208 can be implemented in other wellbore orientations.
  • the logging system 1208 may be adapted for horizontal wellbores, slant wellbores, curved wellbores, vertical wellbores, or combinations of these.
  • the illustrative logging system 1208 includes an acoustic imaging tool 1202, surface equipment 1212, and a tool controller 1210.
  • acoustic imaging tool 1202 is a downhole acoustic imaging tool that operates while disposed in wellbore 1204, as described herein.
  • the example surface equipment 1212 shown in FIG. 12A may operate at or above the surface 1206, for example, near a well head 1205 of wellbore 1204, to position acoustic imaging tool 1202 and optionally other downhole equipment or other components of the well system 1200a.
  • Tool controller 1210 may be operable to control surface equipment and to receive and analyze logging and imaging data from the acoustic imaging tool 1202.
  • Logging system 1208 can include additional or different components or features, and such may be arranged and operated as represented in FIG. 12A or in another suitable manner.
  • tool controller 1210 can be implemented as a component of, or can be integrated with one or more components of, the surface equipment 1212, the acoustic imaging tool 1202, or both to implement the methods described herein.
  • tool controller 1210 can be implemented as one or more discrete computing system structures separate from surface equipment 1212 and acoustic imaging tool 1202.
  • controller 1210 may be located entirely within acoustic imaging tool 1202, and controller 1210 and acoustic imaging tool 1202 can operate concurrently while disposed in wellbore 1204.
  • tool controller 1210 is shown above surface 1206 in the example shown in FIG. 12A , all or part of the tool controller 1210 may reside below surface 1206, for example, at or near the location of the acoustic imaging tool 1202.
  • Well system 1200a can include communication or telemetry equipment that provides a communication link 1280 between tool controller 1210, acoustic imaging tool 1202, and optionally other components of the logging system 1208.
  • the components of logging system 1208 can each include one or more transceivers or similar apparatus for wired or wireless data communication among the various components.
  • the logging system 1208 can include systems and apparatus for wireline telemetry, wired pipe telemetry, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, or a combination of these other types of telemetry.
  • acoustic imaging tool 1202 receives commands, status signals, or other types of information from tool controller 1210 or another source.
  • tool controller 1210 receives logging data, status signals, or other types of information from acoustic imaging tool 1202 or another source.
  • Logging operations can be performed in connection with various types of downhole operations at various stages in the lifetime of a well system.
  • Structural attributes and components of surface equipment 1212 and acoustic imaging tool 1202 can be adapted for various types of logging operations. For example, logging may be performed during drilling operations, during wireline logging operations, or in other contexts.
  • surface equipment 1212 and acoustic imaging tool 1202 may include, or may operate in connection with drilling equipment, wireline logging equipment, or other equipment for other types of operations.
  • FIG. 12B shows an exemplary well system 1200b that includes acoustic imaging tool 1202 in a wireline logging environment.
  • surface equipment 1212 includes a platform above surface 1206 that is equipped with a derrick 1232 or a winch 1233 that supports a conveyance 1234 that extends into wellbore 1204.
  • Wireline logging operations can be performed, for example, after a drilling string is removed from wellbore 1204 to allow acoustic imaging tool 1202 to be lowered by wireline or logging cable into the wellbore 1204.
  • acoustic imaging tool 1202 can be suspended in wellbore 1204 by a conveyance 1234, which may be a coiled tubing, wireline cable, or another structure that connects the tool to a surface control unit or other components of surface equipment 1212.
  • conveyance 1234 which may be a coiled tubing, wireline cable, or another structure that connects the tool to a surface control unit or other components of surface equipment 1212.
  • acoustic imaging tool 1202 is lowered to the bottom of a region of interest and subsequently pulled upward (e.g., at a substantially constant speed) through the region of interest.
  • FIG. 12C shows an exemplary well system 1200c that includes acoustic imaging tool 1202 in an LWD environment. Drilling is commonly carried out using drill pipes connected together to form a drill string 1240 that is lowered through a rotary table into wellbore 1204. In some cases, a drilling rig 1242 at surface 1206 supports drill string 1240, as drill string 1240 is operated to drill a wellbore penetrating subterranean region 120. Drill string 1240 may include, for example, a kelly, drill pipe, a bottom hole assembly, and other components. The bottom hole assembly may include drill collars, drill bits, acoustic imaging tool 1202, and other components.
  • Acoustic imaging tool 1202 can be deployed in the wellbore 1204 on jointed drill pipe, hardwired drill pipe, or other deployment hardware.
  • acoustic imaging tool 1202 collects data during drilling operations as it moves downward through the region of interest during drilling operations, as described herein.
  • acoustic imaging tool 1202 collects data while the drilling string 1240 is moving, for example, while it is being run in or tripped out of wellbore 1204. In other embodiments, however, acoustic imaging tool 1202 is held in place, acoustic measurements are acquired, the tool is shifted, more signals are acquired, etc., as described herein.
  • acoustic imaging tool 1202 collects data at discrete logging points in the wellbore 1204. For example, acoustic imaging tool 1202 can move upward or downward incrementally (or radially) to each logging point at a series of depths in wellbore 1204. At each logging point, instruments in acoustic imaging tool 1202 perform measurements within the wellbore. The measurement data can be communicated to tool controller 1210 for storage, processing, and analysis. Such data may be gathered and analyzed during drilling operations (e.g., during LWD operations), during wireline logging operations, or during other types of activities.
  • Tool controller 1210 can receive and analyze the measurement data from acoustic imaging tool 1202 to detect and characterize fluid flow, provide images of the wellbore and other objects within the wellbore, such as fractures, sand, stuck pipe, scale, and characterize the casing inner wall, its dimensions, and the presence or absence of features along the casing wall, as described herein.
  • the embodiments disclosed herein may be deployed via slickline, coil tubing, measurement-while-drilling ("MWD”) or other downhole tubular assemblies.
  • the acoustic tools are coupled to processing circuitry (e.g., controllers) that act as a data acquisition and/or processing system to analyze amplitude data and perform the methods described herein.
  • the processing circuitry may include at least one processor, a non-transitory, computer-readable storage (also referred to herein as a "computer-program product”), transceiver/network communication module, optional I/O devices, and an optional display (e.g., user interface), all interconnected via a system bus.
  • the network communication module is a network interface card ("NIC") and communicates using the Ethernet protocol.
  • the network communication module may be another type of communication interface such as a fiber optic interface and may communicate using a number of different communication protocols.
  • Software instructions executable by the processor for implementing software instructions in accordance with the illustrative methods described herein, may be stored in storage or some other computer-readable medium.
  • the processing circuitry may be connected to one or more public (e.g ., the Internet) and/or private networks via one or more appropriate network connections. It will also be recognized that the software instructions may also be loaded into storage from a CD-ROM or other appropriate storage media via wired or wireless methods.
  • embodiments of the disclosure may be practiced with a variety of computer-system configurations, including hand-held devices, multiprocessor systems, microprocessor-based or programmable-consumer electronics, minicomputers, mainframe computers, and the like. Any number of computer-systems and computer networks are acceptable for use with the present disclosure.
  • Embodiments of the disclosure may be practiced in distributed-computing environments where tasks are performed by remote-processing devices that are linked through a communications network.
  • program modules may be located in both local and remote computer-storage media including memory storage devices.
  • the present disclosure may therefore, be implemented in connection with various hardware, software or a combination thereof in a computer system or other processing system.
  • the imaging techniques described herein may be performed in real-time to update production, enhance oil recovery (“EOR”) operations, and/or other operations.
  • FIG. 13 is a flow chart of a method for imaging a borehole using an acoustic tool.
  • the acoustic imaging tool is deployed downhole along a borehole to a desired axial position.
  • ultrasonic acoustic impulses are transmitted toward the borehole wall, where they are refracted and received by one or more tool receivers at block 1306.
  • processing circuitry calculates the amplitude of the rerated ultrasonic waves to generate the borehole images as described herein at block 1310.
  • the borehole images may be applied to plan, conduct, analyze, or otherwise enhance any variety of downhole related applications (e.g ., fracture identification, structural dip analysis, stress analysis, borehole stability and breakout analysis, borehole profiling and calculation of cement volume).
  • the embodiments and methods described herein provide a variety of advantages. Compared to conventional velocity imaging methods, the present disclosure provides a higher contrast in the image produced, because the amplitude of a refracted wave is more sensitive to borehole discontinuity than sound velocity. For example, in FIG. 9 , the simulation result has shown more than a 100% increase of amplitude. However, the same simulation result produced a 20% reduction of measurement using the velocity method.
  • the methods described herein are also very sensitive to thin cracks ( e.g., provides clear detection of cracks with less than 1mm in width as demonstrated with simulation data).
  • Embodiments of the disclosure are also sensitive to borehole surface discontinuities, such as fractures, or enlarged boreholes due to washout, while conventional velocity-based approaches are affected other conditions such as stress state at the borehole surface and variations of rock properties.
  • the amplitude approach of the present disclosure also makes use of shear waves, which are much higher in amplitude than compressional wave as shown in both simulation and experimental data.
  • the conventional velocity based methods require accurate detection of arrival time, which can be difficult to identify accurately due to the presence of preceding compressional waves.
  • fractures are encountered (using conventional velocity based methods)
  • the waveforms spread in the time domain and mix into shear wave arrival, thus rendering the results almost useless.

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  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geophysics (AREA)
  • Mining & Mineral Resources (AREA)
  • General Physics & Mathematics (AREA)
  • Remote Sensing (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Acoustics & Sound (AREA)
  • Electromagnetism (AREA)
  • Condensed Matter Physics & Semiconductors (AREA)
  • High Energy & Nuclear Physics (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Investigating Or Analyzing Materials By The Use Of Ultrasonic Waves (AREA)
  • Ultra Sonic Daignosis Equipment (AREA)

Claims (11)

  1. Verfahren zur akustischen Bohrlochabbildung, umfassend:
    Positionieren eines akustischen Abbildungswerkzeugs (400, 700, 1000, 1200) entlang eines Bohrlochs;
    Übertragen eines Ultraschallimpulses in Richtung einer Bohrlochwand unter Verwendung einer Pitch-Catch-Technik, wobei der Ultraschallimpuls mit der Bohrlochwand interagiert, um eine gebrochene Ultraschallwelle zu erzeugen;
    Empfangen der gebrochenen Ultraschallwelle unter Verwendung mehrerer Empfänger (410, 710, 1010);
    Berechnen einer Amplitude der gebrochenen Ultraschallwelle; und
    Erzeugen eines Bildes des Bohrlochs unter Verwendung der Amplitude der gebrochenen Ultraschallwelle,
    wobei das Bild durch Berechnung eines Amplitudenabfalls der gebrochenen Ultraschallwelle erzeugt wird, wobei der Amplitudenabfall durch eine Wechselwirkung zwischen dem Ultraschallimpuls und einer Materialdiskontinuität in der Bohrlochwand verursacht wird, die zu der gebrochenen Ultraschallwelle führt.
  2. Verfahren zur akustischen Bohrlochabbildung nach Anspruch 1, das ferner das Identifizieren von Diskontinuitäten in der Bohrlochwand unter Verwendung des Bildes umfasst.
  3. Verfahren zur akustischen Bohrlochabbildung nach Anspruch 1, wobei:
    das akustische Abbildungswerkzeug (400, 700, 1000, 1200) als Teil einer Anordnung zur Aufzeichnung während des Bohrens entlang des Bohrlochs positioniert wird.
  4. Verfahren zur akustischen Bohrlochabbildung nach Anspruch 1, wobei die gebrochene Ultraschallwelle unter Verwendung eines Empfängerarrays des akustischen Abbildungswerkzeugs (400, 700, 1000, 1200) empfangen wird.
  5. Verfahren zur akustischen Bohrlochabbildung nach Anspruch 1, wobei das Erzeugen des Amplitudenbildes Folgendes umfasst:
    Annäherung des Amplitudenabfalls als Trend,
    wobei Abweichungen vom Trend zur Identifizierung von Brüchen in der Bohrlochwand genutzt werden.
  6. Verfahren zur akustischen Bohrlochabbildung nach Anspruch 1, wobei:
    das akustische Abbildungswerkzeug (400, 700, 1000, 1200) einen oder mehrere Empfänger (410, 710, 1010) aufweist; und
    das Verfahren ferner Folgendes umfasst:
    nach dem Empfangen der gebrochenen Ultraschallwelle, Verschieben des akustischen Abbildungswerkzeugs (400, 700, 1000, 1200) azimutal oder axial;
    Übertragen eines zweiten Ultraschallimpulses in Richtung der Bohrlochwand;
    Empfangen einer zweiten gebrochenen Ultraschallwelle; und
    Berechnen einer Amplitude der zweiten gebrochenen Ultraschallwelle, die zum Erzeugen des Bildes des Bohrlochs verwendet wird.
  7. Akustisches Bohrlochabbildungswerkzeug (400, 700, 1000, 1200), umfassend:
    einen Sender zum Übertragen eines Ultraschallimpulses in Richtung einer Bohrlochwand unter Verwendung einer Pitch-Catch-Technik,
    wobei der Ultraschallimpuls mit der Bohrlochwand interagiert, um eine gebrochene Ultraschallwelle zu erzeugen;
    einen oder mehrere Empfänger (400, 700, 1000, 1200) zum Empfangen der gebrochenen Ultraschallwellen; und
    Verarbeitungsschaltkreise, die kommunikationsmäßig mit dem Sender und den Empfängern (410, 710, 1010) verbunden sind, um dadurch die folgenden Operationen auszuführen:
    Berechnen einer Amplitude der gebrochenen Ultraschallwelle; und
    Erzeugen eines Bildes des Bohrlochs unter Verwendung der Amplitude der gebrochenen Ultraschallwelle, wobei das Bild durch Berechnen eines Amplitudenabfalls der gebrochenen Ultraschallwelle erzeugt wird, wobei der Amplitudenabfall durch eine Wechselwirkung zwischen dem Ultraschallimpuls und einer Materialdiskontinuität in der Bohrlochwand verursacht wird, die zu der gebrochenen Ultraschallwelle führt.
  8. Akustisches Bohrlochabbildungswerkzeug (400, 700, 1000, 1200) nach Anspruch 7,
    ferner umfassend das Identifizieren von Brüchen in der Bohrlochwand unter Verwendung des Bildes.
  9. Akustisches Bohrlochabbildungswerkzeug (400, 700, 1000, 1200) nach Anspruch 7, wobei:
    das akustische Bildgebungswerkzeug (400, 700, 1000, 1200) Teil einer Anordnung zur Aufzeichnung während des Bohrens ist;
    das akustische Bildgebungswerkzeug (400, 700, 1000, 1200) Teil einer drahtgebundenen Anordnung ist; oder
    der Empfänger ein Empfängerarray ist.
  10. Akustisches Bohrlochabbildungswerkzeug (400, 700, 1000, 1200) nach Anspruch 7, wobei das Erzeugen des Amplitudenbildes Folgendes umfasst:
    Berechnen eines Amplitudenabfalls der gebrochenen Ultraschallwelle; und
    Annäherung des Amplitudenabfalls als Trend,
    wobei Abweichungen vom Trend zur Identifizierung von Brüchen in der Bohrlochwand genutzt werden.
  11. Akustisches Bohrlochabbildungswerkzeug (400, 700, 1000, 1200) nach Anspruch 7, wobei:
    der Empfänger einen oder mehrere Empfänger (410, 710, 1010) umfasst, die azimutal oder axial verschiebbar sind; und
    die Operationen ferner Folgendes umfassen:
    nach dem Empfangen der gebrochenen Ultraschallwelle, Verschieben des akustischen Abbildungswerkzeugs (400, 700, 1000, 1200) azimutal oder axial;
    Übertragen eines zweiten Ultraschallimpulses in Richtung der Bohrlochwand;
    Empfangen einer zweiten gebrochenen Ultraschallwelle; und
    Berechnen einer Amplitude der zweiten gebrochenen Ultraschallwelle, die zum Erzeugen des Bildes des Bohrlochs verwendet wird.
EP16888549.9A 2016-11-04 2016-11-04 Bohrlochbildgebung mithilfe von amplituden von gebrochenen akustikwellen Active EP3500727B1 (de)

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US11243326B2 (en) 2022-02-08
EP3500727A4 (de) 2020-05-06
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AR109801A1 (es) 2019-01-23
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